Methods and apparatus for electric power grid frequency stabilization

ABSTRACT

A method and apparatus for operating a combined-cycle power system is provided. The system is coupled to an electric power grid. The system includes at least one electric power generator, at least one steam turbine coupled to the generator, at least one combustion turbine coupled to the generator, and at least one steam source that is in flow communication with the steam turbine. The method includes operating the system at a first power output level with the steam turbine and the combustion turbine being synchronized to an operating frequency of the grid, so that the steam turbine, the combustion turbine, and the grid are operating at a frequency substantially similar to a standardized grid frequency value. The method also includes sensing a grid frequency deviation away from the standardized grid frequency value. The method further includes accelerating or decelerating the turbines and facilitating a predetermined rate of grid frequency recovery for a predetermined period of time, such that the predetermined rate of frequency recovery is substantially uniform.

BACKGROUND OF THE INVENTION

This invention relates generally to electric power grids and moreparticularly, to methods and apparatus for operating combined-cyclepower systems.

The term “full load” is used herein interchangeably with “rated output”and “maximum continuous rating” (MCR). These terms refer to an upperrange of continuous operation output for the power system and itsassociated components. “Partial load” refers to an output level belowfull load.

Electric power grids typically include a number of power generatingsystems to supply electricity to the grid and a number of electricityconsumers that draw electricity from the grid. When the generation andconsumption of electricity are substantially equal, the grid frequencyis substantially constant. Grid frequency is normally a parametermaintained at a substantially stable value. Examples of nominal standardgrid frequencies for the European and North American systems are 50 Hzand 60 Hz, respectively.

Frequency deviations of a transient nature may result from increased ordecreased consumption and/or removal or addition of power generationsystems. Increased consumption and removal of power generation systemstends to cause a decrease of the grid frequency. Decreased consumptionand addition of power generation systems tends to cause an increase ofthe grid frequency. Power consumption and power generation aretime-dependent variables which may cause frequency variations in a rangeof approximately +0.5 Hz to −0.5 Hz. Generally, frequency transients areof a short duration, i.e., measured in seconds to minutes, and asdiscussed above, small magnitudes. The magnitude of a frequencytransient is typically influenced by a ratio of the magnitude of a powervariation to the total power level within the grid and associatedinterconnected grids throughout the duration of the variation. Theaforementioned small magnitude frequency transients are consistent withthe small size of a typical power variation as compared to the typicallylarge size of nominal interconnected grids. Also, in general, powergrids tend to be self-correcting with respect to maintaining gridfrequency within a substantially constant range. For example, in theevent of a frequency deviation from a standard value, a near-termvariation in power generation spread over a number of power generatorsystems may be facilitated by at least one control system and at leastone control strategy to mitigate the magnitude and the duration of thefrequency transient such that frequency transients normally do notimpact consumers.

Larger frequency transients such as transients greater thanapproximately +0.5 Hz to −0.5 Hz and due, for example, to a frequencydecrease as a result of an immediate loss of one or more powergenerators, sometimes referred to as a trip, may tend to induce a largefrequency decrease. One possible method to mitigate the frequencytransient magnitude and duration is to have some amount of standby powergeneration capacity, sometimes referred to as system reserve, availablewithin the grid to respond to the frequency decrease within seconds ofthe transient. For example, a particular generating unit on the grid maybe induced to initiate a fast increase in its associated powergeneration output to the grid.

Many known power generation facilities include either steam turbinegenerators (STG), combustion turbine generators (CTG), or somecombination thereof. These configurations typically include a turbinerotatably coupled to an associated electric generator. The generatorfrequency is normally synchronized to the electric power grid frequencyand rotates at a speed substantially similar to the grid frequency.

Many known STGs operate in flow communication with a steam generationapparatus, for example, a boiler. Generally, air and fuel are combustedto release thermal energy that is subsequently used to boil water togenerate steam. The steam generated is channeled to a turbine whereinthe thermal energy of the steam is converted to mechanical energy torotate the rotor of the turbine. The power generated is proportional tothe rate of steam flow to the turbine.

One known method of maintaining a power reserve is to operate a STG withat least one associated steam supply control valve in a partially open,or throttled, position such that the steam generator, the STG and thepower grid are in an equilibrium, sometimes referred to as asteady-state condition, operating at some value less than full ratedload of the steam generator and STG arrangement. The difference betweenfull load and partial load is often referred to as spinning reserve. Acontroller is utilized to sense a decrease in system frequency and togenerate a control signal transmitted to the steam valve within secondsof sensing a frequency transient. The control signal causes the valve tomove to a more open position and thermal energy stored within thecomponents of the steam generation apparatus, for example, thesuperheater, begins to be removed immediately via increased steam flowthrough the steam generator. Cooling fluid, air and fuel aresubsequently increased over time to facilitate establishing a modifiedequilibrium between the steam generator, the STG and the power grid.However, many steam generator and STG combinations may take two to fiveminutes to attain the modified equilibrium while operating withinpredetermined parameters to mitigate the potential for increased stressand wear on affected components. Also, the amount of thermal energytypically stored in the aforementioned manner is limited. In addition,many steam generator and STG combinations may not effectively respond toa grid frequency transient with a stable, controlled response. Forexample, the aforementioned steam valve to the STG may open too quicklyand deplete the thermal energy reserve too rapidly to deliver asustained, effective response. Alternatively, the steam valve to the STGmay open too slowly to deliver a timely, effective response.

Many known CTGs ignite a fuel-air mixture in a combustor assembly andgenerate a combustion gas stream that is channeled to a turbine assemblyvia a hot gas path. Compressed air is channeled to the combustorassembly by a compressor assembly that is normally coupled to theturbine, i.e., the compressor, turbine and generator rotate at the samespeed. The power generated is proportional to the rate of combustion gasflow to the turbine and the temperature of the gas flow stream.Typically, many known CTGs have an operationally more dynamic behaviorthan STG (and their associated steam sources), therefore, CTGs mayrespond to system transients more rapidly.

One known method of maintaining a power reserve is to operate a CTG withat least one associated air guide vane and at least one fuel supplyvalve in a partially open, or throttled, position such that the CTG andthe power grid are in an equilibrium, operating at some value less thanthe full rated load of the CTG. As discussed above for the STG, thedifference between full load and the partial load is often referred toas spinning reserve. A controller senses a decrease in grid frequencyand generates a signal that causes the air inlet guide vane and the fuelsupply valve to open further within seconds of sensing the frequencytransient. Since the compressor, the turbine and the generator arecoupled to the same shaft, and since the generator that is synchronizedto the grid decelerates as grid frequency is decreased, there exists aninitial bias to channel less air into the CTG. This condition initiatesa decreasing bias in CTG electric power generation that may negativelyimpact subsequent activities to increase CTG electric power generation.Furthermore, a bias to decrease air flow followed by a bias to increaseair flow through the associated compressor may introduce a potential fora compressor surge, i.e., a substantially uncontrolled fluctuation ofair flow and compressor discharge pressure, with surge potential beingmore pronounced at the lower end of compressor rated air flows. As thevane opens to increase the air flow and as the valve opens to increasethe fuel flow, the mass flow rate of the combustion gas and thecombustion gas temperature begin to increase within seconds of sensingthe system frequency transient. Air and fuel are subsequently increasedover time to facilitate establishing a modified equilibrium between theCTG and the power grid. In order to overcome the initial bias todecrease generation and then to accelerate the CTG, the combustionturbine may need to peak-fire, i.e., rapidly increase the rate ofcombustion to rapidly increase gas stream temperature while thesubsequent increase of air flow follows. While the CTG may exhibit amore dynamic ability to respond to a frequency transient, many knownCTGs may have temperature and temperature gradient limitations that mayextend the time duration for increasing gas stream temperatures in orderto mitigate stresses on a portion of the materials associated with theCTG. Otherwise, component stresses may increase and their associatedlife span may be negatively affected.

Many known steam generation apparatus and CTG are thermally mostefficient operating in a range near the upper end of their operationalpower generation range. Maintaining a power generation level below thatrange may decrease thermal efficiency with a subsequent increase in costof operation as well as possibly deny the owners of the facilitypotential revenue from the sale of the electric power held in reserveand routinely not generated.

Many known combined-cycle electric power generation facilities typicallyinclude at least one CTG and at least one STG. Some known configurationsfor such facilities include channeling the combustion gas exhaust from aCTG to a heat recovery steam generator (HRSG), wherein the thermalenergy from the combustion gas exhaust boils water into steam, the steamsubsequently being channeled to a STG. Typically, combined-cyclefacilities are configured to use a CTG as the primary response mechanismfor grid frequency transients while a STG is maintained as the secondaryresponse. While this physical configuration offers benefits ofefficiency and therefore economy of operation, the responseconfiguration and method includes at least some of the aforementionedchallenges in responding rapidly and effectively to a grid frequencytransient.

BRIEF DESCRIPTION OF THE INVENTION

In one aspect, a method of operating a combined-cycle power system isprovided. The system is coupled to an electric power grid. The systemincludes at least one electric power generator, at least one steamturbine coupled to the generator, at least one combustion turbinecoupled to the generator, and at least one steam source having a thermalenergy reservoir. The thermal energy reservoir is in flow communicationwith the steam turbine via at least one control valve. The methodincludes operating the steam turbine at a first electric power output,operating the combustion turbine at a first electric power output, andoperating the steam source at a first thermal energy level. The steamturbine has at least one control valve in a first position and thecombustion turbine has at least one air inlet guide vane in a firstposition. The steam turbine and the combustion turbine are synchronizedto an operating frequency of the grid, so that the steam turbine, thecombustion turbine, and the grid are operating at a frequencysubstantially similar to a standardized grid frequency value. The methodalso includes sensing a grid frequency deviation away from thestandardized grid frequency value. Upon the occurrence of such adeviation, the method further includes moving the at least one steamturbine control valve to a second position, causing a thermal energytransfer between the thermal energy reservoir and the steam turbine, andmoving the thermal energy reservoir energy level to a second energylevel, thereby facilitating a predetermined rate of a grid frequencyrecovery for a predetermined period of time, such that the predeterminedrate of frequency recovery is substantially uniform. The method alsoincludes moving the at least one combustion turbine air inlet guide vaneto a second position, thereby facilitating a predetermined rate of agrid frequency recovery for a predetermined period of time.

In another aspect, an electric power grid frequency control sub-systemfor a combined-cycle power system is provided. The control sub-systemincludes at least one steam turbine. The steam turbine includes at leastone pipe and the pipe includes at least one steam flow control valve.The sub-system also includes at least one steam source in flowcommunication with the steam turbine via the pipe. The steam sourceincludes at least one thermal energy reservoir. The sub-system furtherincludes at least one combustion turbine and the combustion turbineincludes at least one air inlet guide vane. The sub-system also includesat least one electric power generator. The generator is electricallycoupled to an electric power grid and the generator frequency and thegrid frequency are synchronized to an operating frequency of the grid,such that the steam turbine, the combustion turbine, and the grid areoperating at a frequency substantially similar to a standardized gridfrequency value. The sub-system further includes a plurality of processfeedback mechanisms and the feedback mechanisms include a plurality ofprocess measurement sensors. The sub-system also includes at least oneelectronic controller. The at least one electronic controller includesat least one electronically stored control program, a plurality ofelectronic input channels, a plurality of electronic output channels,and at least one operator interface device. The at least one steam flowcontrol valve and the at least one air inlet guide vane cooperate tocontinuously facilitate a predetermined rate of a grid frequencyrecovery for a predetermined period of time, such that the predeterminedrate of frequency recovery is substantially uniform.

In a further aspect, a combined-cycle power system is provided. Thesystem includes at least one steam turbine. The steam turbine includesat least one pipe and the pipe includes at least one steam flow controlvalve. The at least one steam flow control valve is moved toward asubstantially open position in response to a grid under-frequencycondition and toward a substantially closed position in response to agrid over-frequency condition. The system also includes at least onesteam source in flow communication with the steam turbine via the pipe.The steam source includes at least one thermal energy reservoir and theat least one thermal energy reservoir includes at least one cavity. Thesystem further includes at least one combustion turbine. The combustionturbine includes at least one air inlet guide vane. The at least air oneinlet guide vane is moved toward a substantially open position inresponse to a grid under-frequency condition and toward a substantiallyclosed position in response to a grid over-frequency condition. Thesystem also includes at least one electric power generator. Thegenerator is electrically coupled to an electric power grid. Thegenerator frequency and the grid frequency are synchronized to anoperating frequency of the grid, such that the steam turbine, thecombustion turbine, and the grid are operating at a frequencysubstantially similar to a standardized grid frequency value. The systemfurther includes a plurality of process feedback mechanisms and thefeedback mechanisms include a plurality of process measurement sensors.The system also includes at least one electronic controller. The atleast one electronic controller includes at least one electronicallystored control program, a plurality of electronic input channels, aplurality of electronic output channels, and at least one operatorinterface device. The at least one steam flow control valve and said atleast one air inlet guide vane cooperate to continuously facilitate apredetermined rate of a grid frequency recovery for a predeterminedperiod of time, such that the predetermined rate of frequency recoveryis substantially uniform.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of an exemplary combined-cycle powersystem;

FIG. 2 is a graphical illustration of an exemplary response of thecombined-cycle power system in FIG. 1;

FIG. 3 is a flow chart of an exemplary method of response to an electricpower grid under-frequency condition that may be used with thecombined-cycle power system in FIG. 1; and

FIG. 4 is a flow chart of an exemplary method of response to an electricpower grid over-frequency condition that may be used with thecombined-cycle power system in FIG. 1.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 is a schematic illustration of an exemplary combined-cycle powergeneration system 100. System 100 includes at least one combustionturbine air inlet guide vane 102, a combustion turbine compressor 104that is in flow communication with at least one combustor 106, a fuelstorage facility 108 also in flow communication with combustor 106 viaat least one fuel supply valve 110, a combustion turbine 112, a commonshaft 114, a combustion turbine generator (CTG) 116 that is rotatablycoupled to compressor 104 and turbine 112 via shaft 114, a generatoroutput connection 118, a plurality of CTG sensors 120, and a combustionturbine exhaust gas duct 122 in flow communication with a heat recoverysteam generator (HRSG) 124. HRSG 124 includes a first set of tube banks126, a second set of tube banks 128, a steam drum 130, and a third setof tube banks 132 with tube banks 126, 128, 132 and drum 130 in flowcommunication with each other. System 100 further includes a superheatedsteam header 134 in flow communication with a steam turbine 138 via atleast one steam turbine control valve 136. A common shaft 140 rotatablycouples turbine 138 to a steam turbine generator (STG) 142. System 100further includes a plurality of STG sensors 144 and a generator outputconnection 146. Furthermore, a steam turbine steam exhaust duct 148, aheat exchange apparatus 150, a steam condensing apparatus 151 withcooling water flow, a condensate supply header 152, acondensate/feedwater pump 154, and a feedwater supply header 156 are inflow communication with each other. A HRSG gas exhaust duct 158 is inflow communication with HRSG 124 and a stack 160. Automated and manualcontrol of system 100 is facilitated with a controller 162. Generators116 and 142 are interconnected with an electric power grid 164 viatransmission lines 166. Consumers 168 are connected to grid 164 as areother power generation facilities 170.

Electric power is generated by CTG 116. Compressor 104 channels air tocombustor 106 through air inlet guide vane 102. Alternatively, aplurality of fast-acting guide vanes may be used. Fuel is channeled tocombustor 106 from storage facility 108 via fuel valve 110. In theexemplary embodiment storage facility 108 is a natural gas supplystation. Alternatively, facility 108 may be a natural gas storage tank,a fuel oil storage tank or a fuel oil trailer. Also, alternatively,system 100 may include an Integrated Gasification Combined Cycle (IGCC)plant wherein facility 108 generates a synthetic gas. Combustor 106ignites and combusts the fuel with the air to generate high temperature,i.e., approximately 1316° Celsius (C) (2400° Fahrenheit (F)), combustiongas that is subsequently channeled to turbine 112. In the exemplaryembodiment, combustor 106 may ignite and combust natural gas or fueloil, i.e., turbine 112 is a duel-fuel unit. Thermal energy in thecombustion gas is converted to rotational energy in turbine 112. Asdescribed above, turbine 112 is rotatably coupled to compressor 104 andgenerator 116 via shaft 114, and compressor 104 and generator 116 rotatewith turbine 112 with substantially similar rotational velocities.Generator 116 generates a voltage and an electric current at a frequencydirectly proportional to shaft 114 rotational velocities when generator116 is not synchronized to grid 164. The electric power output ofgenerator 116 is transmitted to grid 164 via interconnection 118 at afrequency substantially similar to grid 164 frequencies when generator116 is synchronized to grid 164. Generator 116 may be controlled via anexcitation system (not shown in FIG. 1). Plurality of sensors 120 mayinclude at least one current transducer (not shown in FIG. 1), onevoltage transducer (not shown in FIG. 1) and one frequency transducer(not shown in FIG. 1). The outputs of sensors 120 are transmitted tocontroller 162.

Electric power is also generated with STG 142. HRSG 124 transmitssuperheated steam to turbine 138 via steam header 134 and control valve136. Control valve 136 is continuously biased via controller 162 tomodulate steam flow to turbine 138 as discussed further below.Controller 162 receives input from sensors 144. In the exemplaryembodiment, sensors 144 include pressure transducers immediatelyupstream and downstream of valve 136. Thermal energy in the steam isconverted to mechanical energy in turbine 138 that rotates shaft 140. Asdescribed above, turbine 138 is rotatably coupled to generator 142 viashaft 140, and STG 142 rotates with turbine 138 with substantiallysimilar rotational velocities. Generator 142 generates a voltage and anelectric current at a frequency directly proportional to shaft 140rotational velocities when generator 142 is not synchronized to grid164. The electric power output of generator 142 is transmitted to grid164 via interconnection 146 at a frequency substantial similar to grid164 frequency when generator 142 is synchronized to grid 164. Generator142 may be controlled via an excitation system (not shown in FIG. 1).Plurality of sensors 144 may include at least one current transducer(not shown in FIG. 1), one voltage transducer (not shown in FIG. 1) andone frequency transducer (not shown in FIG. 1). The outputs of sensors144 are transmitted to controller 162.

Alternatively, a steam turbine assembly that includes a variety ofconfigurations may be used. For example, a steam turbine assembly mayinclude a high pressure section, an intermediate pressure section, and alow pressure section. Also, for another example, a steam turbineassembly and a combustion turbine assembly may be rotatably coupled to asingle shaft rotatably driving a single generator.

Steam for turbine 138 is generated via HRSG 124. Alternatively, HRSG 124may be replaced by an independently-fired boiler apparatus. In theexemplary embodiment, HRSG 124 receives exhaust gases from turbine 112via duct 122. Generally, gas exhaust from combustion turbines includesusable thermal energy, with a temperature range of approximately 538° C.to 649° C. (1000° F. to 1200° F.), that is not converted to mechanicalenergy within turbine 112 to rotate shaft 114. Exhaust gases flowthrough HRSG 124 from the higher temperature steam generatingcomponents, illustrated in the exemplary embodiment as superheater tubebanks 132, to the lower temperature tube banks 128 firstly, and thentube banks 126. Gas is channeled to duct 158 and subsequently to stack160, generally via environmental control sub-systems (not shown in FIG.1), that channels the gases to the environment. Generally, substantiallylittle usable thermal energy remains in the gas stream upon exhaust tothe environment.

Water is boiled to generate steam in HRSG 124. Sub-cooled water isstored in heat exchange apparatus 150. In the exemplary embodiment,apparatus 150 includes a main condenser that receives steam from turbine138 via duct 148. Apparatus 150 also includes a cavity (not shown inFIG. 1) for water storage and condensing apparatus 151. In the exemplaryembodiment, apparatus 151 includes a plurality of tubes that channelscooling water from a source (not shown in FIG. 1) that may include acooling tower, a lake or a river. Steam exhausted from turbine 138 flowsover the external surfaces of tubes 151 wherein thermal energy istransferred from the steam to the cooling water via tube 151 walls.Thermal energy removal from the steam induces a change in state of thefluid to a liquid form. The liquid collects within apparatus 150 fromwhere it is channeled to pump 154 via suction header 152. In theexemplary embodiment, pump 154 is a feedwater pump. Alternatively, pump154 may be a series of condensate booster pumps, condensate pumps andfeedwater pumps. Also, alternatively, at least one feedwater heater thatpreheats feedwater prior to entry into HRSG 124 may be included insystem 100. Feedwater enters first tube bank 126 and thermal energy istransferred from the combustion gas stream that flows over tube bank 126surfaces to the feedwater within tubes 126. Heated feedwater ischanneled to tube banks 128 wherein thermal energy is transferred to thefeedwater in a manner substantially similar to that associated withtubes 126 with the exception that the gas stream has a highertemperature in the vicinity of tubes 128. Feedwater, that by this pointis a combination of water and steam, is channeled to steam drum 130 fromtubes 128. In the exemplary embodiment, steam drum 130 includes aplurality of steam/water separation devices (not shown in FIG. 1) thatremoves water from the steam and water flow stream and return the waterto drum 130. Steam, with substantially most of the water removed, isfurther channeled to superheater tube banks 132 wherein the exhaust gasstream from turbine 112 is at its highest temperatures and transfersthermal energy to the steam within tubes 132 in a manner similar to thatfor tubes 126 and 128. Superheated steam is channeled to steam header134 upon exit from HRSG 124.

Electric current from CTG 116 is transmitted to transmission lines 166via interconnection lines 120. Electric current is similarly transmittedto transmission lines 166 from STG 142 via interconnection 146.Transmission lines 166 connect grid 164 with system 100. Other electricpower generation facilities 170 generate and transmit electric powerinto grid 164 for use by consumers 168.

Controller 162 includes a processor (not shown in FIG. 1), a memory (notshown in FIG. 1), a plurality of input channels (not shown in FIG. 1),and a plurality of output channels (not shown in FIG. 1) and may includea computer (not shown in FIG. 1). As used herein, the term computer isnot limited to just those integrated circuits referred to in the art asa computer, but broadly refers to a processor, a microcontroller, amicrocomputer, a programmable logic controller, an application specificintegrated circuit, and other programmable circuits, and these terms areused interchangeably herein. In the exemplary embodiment, memory mayinclude, but is not limited to, a computer-readable medium, such as arandom access memory. Alternatively, a floppy disk, a compact disc—readonly memory (CD-ROM), a magneto-optical disk (MOD), and/or a digitalversatile disc (DVD) may also be used. Also, in the exemplaryembodiment, a plurality of input channels may represent, but not belimited to, computer peripherals associated with an operator interfacesuch as a mouse and a keyboard. Alternatively, other computerperipherals may also be used, for example, a scanner. Furthermore, inthe exemplary embodiment, a plurality of output channels may include,but not be limited to, an operator interface monitor.

Controller 162 receives a plurality of inputs from a plurality ofsensors, some of which include sensors 120 and 144, processes theinputs, generates appropriate outputs based on programmed algorithms anddiscrete circumstances, and transmits signals to the appropriate system100 components to bias those components. For example, in the event of asmall downward frequency transient on grid 164, i.e., approximately 0.5Hz or less, controller 162 will receive a frequency input transmittedfrom sensors 120. Controller 162 subsequently induces an opening biasfor inlet guide vane 102 and fuel valve 110. Inlet guide vane 102 ismodulated throughout the transient such that predetermined margins topotential compressor surge conditions are maintained. Combustion withincombustor 106 increases and induces a similar increase in gas streammass flow rate and gas stream temperature. The change in gas streamtemperature is maintained within a range of predetermined temperatureand temperature gradient parameters to mitigate potential stresses inturbine 112 components. Turbine 112 accelerates and the rotationalacceleration is induced in generator 116 via shaft 114, thereby inducinga partial increase in grid 164 frequency towards the nominal systemfrequency value, for example, 50 Hz for Europe and 60 Hz for NorthAmerica. Similarly, for a sensed increase in grid frequency ofapproximately 0.5 Hz or less, controller 162 receives a frequency inputfrom sensors 120 and induces a closing bias to air guide vane 102 andfuel valve 110 to decrease mass flow rate and temperature of the gasstream generated by combustor 106. The subsequent induced decelerationof shaft 114 via turbine 112 also decelerates CTG 116 and a grid 164frequency decrease towards the nominal value of frequency is induced.

A similar process may be observed for STG 142. Sensors 144 sense adecrease in grid 164 frequency and transmit an associated signal tocontroller 162. Controller 162 induces an opening bias to steam valve136. Valve 136 is opened at a rate consistent with maintaining steamheader 134 pressure upstream and downstream of valve 136 within a rangeof predetermined parameters. Also, appropriate control of HRSG 124 ismaintained such that any subsequent changes in steam temperature aremaintained within a range of predetermined temperature and temperaturegradient parameters to mitigate potential stresses in turbine 138components.

FIG. 2 is a graphical illustration 200 of an exemplary response ofcombined-cycle power system 100 (shown in FIG. 1) to an electric powergrid 164 under-frequency condition. Response graph 200 includes ordinate202 (y-axis) in increments of 2% representing approximate electric poweroutputs of CTG 116 and STG 142 as a function of time. Ordinate 202includes a value of 88% at the origin of graph 200 and 100% as theuppermost limit, corresponding to CTG 116 and STG 142 MCR. Graph 200also includes abscissa (x-axis) 204 that illustrates time in minutesusing one minute increments. Time=0 indicates the initiation of anunder-frequency transient on electric power grid 164. Time=7 minutesillustrates the transient and system 100 response being substantiallycomplete. Curve 206 illustrates a potential CTG 116 output responseversus time. Curve 208 illustrates a potential STG 142 output responseversus time without the invention described herein for comparisonpurposes. Curve 210 illustrates a potential STG 142 output responseversus time with the invention described herein. FIG. 2 is referencedfurther below.

FIG. 3 is a flow chart of an exemplary method 300 of a response to anelectric power grid under-frequency condition that may be used withcombined-cycle power system 100 (shown in FIG. 1). Referring to FIG. 1,method step 302 of exemplary method 300 includes operating STG 142 andCTG 116 at substantially steady-state conditions with both STG 142 andCTG 116 operating at a partial load below MCR. Valve 136, vane 102 andvalve 110 are in throttled positions such that system 100 may referredto as operating in a frequency-sensitive mode of electric powergeneration. Alternatively, system 100 may be operated in a nominaldispatch mode, wherein an electric power dispatching authority directssystem 100 and other facilities 170 generation output. In the exemplaryembodiment, the partial load below MCR is 90% of MCR for CTG 116 and STG142 as illustrated in FIG. 2.

In order to facilitate step 302, valve 136, sensors 144, and controller162 cooperate to operate system 100 in frequency-sensitive mode. Valve136 is configured and positioned and cooperates with controller 162 suchthat valve 136 is in a throttled position. A plurality of valve 136positions between the fully open and fully closed positions, inconjunction with a corresponding HRSG 124 backpressure for eachposition, facilitates generating a particular steam mass flow rate. HRSG124 backpressure facilitates maintaining a reservoir of substantiallyimmediately available power that may be used as described below.Controller 162 transmits signals that move valve 136 appropriately togenerate power while maintaining the appropriate backpressure to respondto a power increase demand. Controller 162 moves valve 136 as a functionof existing power demand, existing steam flow rate, existing gridfrequency, and existing HRSG backpressure. The cooperation of valve 136,controller 162 and sensors 144 are described further below. It is notedthat the aforementioned cooperation permits system 100 to operate atoutput levels that facilitate potential additional revenue generation.

Step 304 of exemplary method 300 includes system 100 sensing anunder-frequency condition on grid 164 via sensors 120 and 144. Thisevent corresponds to time=0 minutes in FIG. 2. The illustratedunder-frequency condition may be a result of a trip of one or moregenerating units 170 or a large increase in electric power demand byconsumers 168 such that a grid frequency decrease may be greater than0.5 Hz below the standard frequency. Controller 162 interprets thetransient as a demand for a rapid electric power generation increasefrom system 100.

Curve 208 of response graph 200 illustrates a potential response of STG142 to the aforementioned under-frequency transient without theinvention discussed herein and is presented for comparison purposes. Inthis circumstance, valve 136 rapidly opens to the substantially fullyopen position. Steam flow to turbine 138 increases rapidly and electricpower generation output of STG 142 increases accordingly to a valuesubstantially similar to 100% of MCR. Electric power output remainssteady at a value substantially similar to 100% of MCR, however, in lessthan one minute power output decreases as steam backpressure upstream ofvalve 136 in HRSG 124 decreases as the thermal energy reserve isdepleted. Curve 206 of response graph 200 illustrates CTG 116 response.Controller 162 begins to move vane 102 and valve 110 towardssubstantially fully open positions. In the exemplary embodiment, inletguide vane 102 is modulated throughout the transient such thatpredetermined margins to potential compressor surge conditions aremaintained. The use of the thermal energy reserve within HRSG 124facilitates vane 102 modulation and subsequently increasing the marginto potential surge conditions. Alternatively, methods for activecompressor surge management may be integrated into the control scheme.Valve 110 responds more rapidly, thereby peak-firing turbine 112 with afuel-rich mixture as the air flow from compressor 104 starts toincrease. It is noted that the response of CTG 116 is slightly slowerthan STG 142 due to the finite period of time associated with valve 110opening (for safety and control purposes) as well as the aforementionedcompressor 104 speed decrease in proportion to the CTG 116 frequencydecrease. These circumstances associated with CTG 116 are compared tothe substantially immediately available additional steam flow capacityresiding in HRSG 124 thermal reservoir.

CTG 116 is maintained at a steady output of approximately 96% to 98% ofMCR as illustrated by curve 206 on response graph 200. The associatedplateau illustrates that CTG 116 initial response is limited to lessthan 100% MCR since the peak-firing increases combustion gas streamtemperature and the gas stream temperature gradient and must becontrolled within a range of predetermined parameters to mitigateinducing thermal stresses in turbine 112 components that may havecontact with the gas stream and to maintain a fuel-to-air ratio withinappropriate guidelines. As increased air flow is induced due to vane 102opening and CTG 116 accelerating, the mass flow rate through turbine 112increases and fuel valve 110 is once again biased to open further toadmit more fuel. As a result, CTG 116 output increases at a steady rateuntil substantially 100% of MCR is attained. It is noted that it takesapproximately two minutes from system 100 sensing the under-frequencycondition to attain the initiation of the steady increase in poweroutput and between six and seven minutes to attain substantially 100%MCR.

As the temperature and the mass flow rate of combustion gas is channeledto HRSG 124 and the associated thermal energy transfer from the gas tothe water/steam circuit within HRSG 124 increases, the decrease in STG142 power output begins to be mitigated and curve 208 follows curve 206within approximately three minutes of initiation of the transient. STG142 attains substantially 100% of MCR within seven minutes of initiationof the transient.

The response of system 100 with the invention to an under-frequencycondition is demonstrated in method step 306 of exemplary method 300.Step 306 includes controller 162 moving valve 136 towards the fully openposition. As described above, controller 162 moves valve 136 as afunction of existing power demand, existing steam flow rate, existinggrid frequency, and existing HRSG backpressure. Sensors 144 transmitgrid frequency, STG 142 power output, steam pressures upstream anddownstream of valve 136, mass flow rate of steam to turbine 138, andvalve 136 position feedback to controller 162. Controller 162 comparesthese signals to predetermined values for the associated parameters,i.e., target values, and transmits the appropriate bias signals to valve136.

Method step 308 of exemplary method 300 includes accelerating STG 142and rapidly increasing STG 142 electric power output as the mass flowrate of steam increases and the increased mass flow rate is translatedinto an increased rate of energy conversion from the thermal energy ofthe steam to the mechanical rotational energy of turbine 138. Curve 210on FIG. 2 illustrates a potential STG 142 output response versus timewith the invention described herein. Valve 136 is opened in cooperationwith sensors 144 and controller 162 as described above such that asubstantially instantaneous increase in power output of STG 142 to arange of approximately 98% to 99% of MCR is attained. However, theincrease is not as pronounced with the invention as without theinvention, thereby facilitating mitigating the short-term thermal energyreserve depletion.

Method step 310 of exemplary method 300 includes rapidly depleting thethermal energy reserve. Controller 162 moves valve 136 in a manner thatmitigates the rate of depletion of the thermal reserve residing in HRSG124, however, the amount of the thermal reserve is finite and begins todeplete rapidly at this point in the system 100 response to thetransient.

Method step 312 of exemplary method 300 includes inducing an openmovement in valve 136 such that valve 136 slowly travels toward thefully open position, thereby slowly increasing the mass flow rate ofsteam to turbine 138.

Method step 314 of exemplary method 300 includes slowly accelerating STG142 and slowly increasing STG output. The controlled, slow rate ofincrease of the mass flow rate of steam to turbine 138 results in aslow, controlled acceleration of STG 142 with an associated increase inpower output.

Method step 316 of exemplary method 300 includes mitigating the rate ofthermal energy reserve removal from the thermal energy reservoir.Controlling the initial open movement of valve 136 such that the initialthermal energy reserve release is controlled and slowly opening valve136 thereafter facilitates mitigating a depletion of the thermal energyreserve prior to additional thermal energy from combustion turbine 112can be channeled to HRSG 124 as described below.

Method step 330 of exemplary method 300 includes initiating peak-firingof combustion turbine 112 via moving fuel valve 110 towards the fullyopen position. Step 330 is typically performed substantiallysimultaneously with method step 306.

Method step 332 of exemplary method 300 includes increasing combustiongas temperature. Increasing the fuel/air ratio within a range ofpredetermined parameters by increasing the fuel input into combustionturbine 112 initiates a temporary peak-firing condition in turbine 112.Controller 162 transmits an open signal to valve 110 such that thetemperature of the combustion gas stream is rapidly increased whilemaintaining the range of gas stream temperature and the rate oftemperature increase of the gas within predetermined parameters.

Method step 334 of exemplary method 300 includes rapidly acceleratingCTG 116 such that a rapid power output increase is induced as thethermal energy within the combustion gas stream increases and turbine112 converts the thermal energy to mechanical rotational energy.

Method step 336 of exemplary method 300 includes moving vane 102 towardsthe fully open position with a subsequent increase in air flow. Step 336is typically initiated substantially simultaneously with method step330.

Method 338 of exemplary method 300 includes increasing the combustiongas mass flow rate. Gas mass flow rate is increased as turbine 112accelerates per method step 334 and compressor 104 accelerates withturbine 112 via shaft 114, and vane 102 is opened toward the fully openposition per method step 336.

Method 340 of exemplary method 300 includes increasing CTG 116 output to100% MCR. As the mass flow rate of air into combustor 106 increases andthe fuel/air ratio is returned to a predetermined range of values,controller 162 transmits open signals to vane 102 and valve 110 tocontinue to accelerate CTG 116 such that mitigating thermal stressparameters of turbine 112 components is facilitated and CTG 116 attainssubstantially 100% of MCR. Referring to FIG. 2, CTG 116 response asillustrated in curve 206 is substantially similar with and without theinvention.

Method step 370 of exemplary method 300 includes increasing the rate ofthermal energy transfer to the steam/water circuit in HRSG 124. Asturbine 112 exhaust temperature increases per method step 332 and isfollowed by an increase in the gas mass flow rate per method step 338,the rate thermal energy transfer from the gas stream into tube banks132, 128 and 126 of HRSG 124 increases.

Method 372 of exemplary method 300 includes increasing the pressure andthe thermal energy within HRSG 124. The increased rate of thermal energytransfer into HRSG 124 thermal energy reservoir counters the thermalenergy removal due to valve 136 opening.

Method 374 of exemplary method 300 includes increasing steam generationin HRSG 124. The increased thermal energy transfer within HRSG 124 ismanifested as an increase in the rate of converting water to steam inthe steam/water circuit.

Method 376 of exemplary method 300 includes increased channeling ofsteam to STG 142. The subsequent increasing of the mass flow rate ofsteam from HRSG 124 to turbine 138 permits continued biasing of valve136 toward the fully open position without depleting the thermal energyreserve.

Method step 378 of exemplary method 300 includes increasing power outputof STG 142 to 100% of MCR. Referring to FIG. 2 valve 136 is furthermoved towards the fully open position at a rate consistent with thefacilitating maintenance of the thermal energy reserve in the HRSG 124thermal reservoir such that a substantially steady rate of power outputincrease is facilitated. It is noted that the increased thermal energyof the combustion gases from turbine 112 transferred to HRSG 124 ismeasured and controlled by controller 162 to facilitate the overallsystem 100 response. It is also noted that the steady ramp illustratedon curve 210 in conjunction with the steady ramp on curve 206facilitates an improved frequency stabilizing response associated withsystem 100.

The discussion of method 300 thus far associated with opening valve 136and depleting and subsequently replenishing the thermal energy reservewithin HRSG 124 assumes a linear rate of valve 136 movement and a linearrate of thermal energy depletion and replenishment. In the event of amore dynamic set of conditions, controller 162 includes sufficientcomputational resources, including the associated programming, tomodulate valve 136 more aggressively through the full range of positionsbetween substantially fully open and substantially fully closed asnecessary to maintain HRSG 124 backpressure between a predeterminedupper pressure value and a predetermined lower pressure value. Anexample of a lower pressure value may be 16,547 kilopascal (kPa) (2400pounds per square inch (psi)) and an example of an upper pressure valuemay be 17,926 kPa (2600 psi). Controller 162 modulates HRSG 124backpressure as described above in a manner that also modulates the rateof variation in HRSG 124 backpressure while accelerating STG 138 andincreasing the thermal energy input rate into HRSG 124 via CTG 112 andduct 122. Given the aforementioned more dynamic conditions and a moreaggressive response, curve 210 (shown in FIG. 2) may be illustrated asless linear and more sinusoidal, or saw toothed while maintaining asubstantially upward slope. Controller 162 includes the computationalresources that mitigate the amplitudes and periods of the sinusoidal orsaw-toothed response to drive the associated response toward asubstantially linear response. Additionally, controller 162 modulatesthe additional fuel and air to CTG 112 such that system 100 overallresponse to a grid 166 under-frequency condition is an increase insystem 100 output frequency. For example, as valve 136 is moved towardthe closed position to maintain HRSG 124 pressure above a lowerthreshold limit, CTG 112 may be accelerated further to maintain system100 response. As valve 136 is moved toward the open position to maintainHRSG 124 pressure below an upper threshold limit, CTG 112 rate ofacceleration may be decreased to maintain system 100 response. Curve 206may also attain a less linear and more sinusoidal, or saw toothed shapewhile maintaining the overall shape as illustrated in FIG. 2.

FIG. 4 is a flow chart of an exemplary method 400 of a response to anelectric power grid over-frequency condition that may be used withcombined-cycle power system 100 (shown in FIG. 1). Referring to FIG. 1,method step 402 of exemplary method 400 includes operating STG 142 andCTG 116 at substantially steady-state conditions with both STG 142 andCTG 116 operating at a partial load below MCR. Valve 136, vane 102 andvalve 110 are in throttled positions such that system 100 may referredto as operating in a frequency-sensitive mode of electric powergeneration. Alternatively, system 100 may be operated in a nominaldispatch mode, wherein an electric power dispatching authority directssystem 100 and other facilities 170 generation output. In the exemplaryembodiment, the partial load below MCR is 90% of MCR for CTG 116 and STG142.

In order to facilitate step 402, valve 136, sensors 144, and controller162 cooperate to operate system 100 in frequency-sensitive mode. Valve136 is configured and positioned and cooperates with controller 162 suchthat valve 136 is in a throttled position. A plurality of valve 136positions between the fully open and fully closed positions, inconjunction with a corresponding HRSG 124 backpressure for eachposition, facilitates generating a particular steam mass flow rate. HRSG124 backpressure facilitates maintaining a reservoir of substantiallyimmediately available capacity to store thermal energy as describedbelow. Controller 162 transmits signals that move valve 136appropriately to generate power while maintaining the appropriatebackpressure to respond to a power decrease demand. Controller 162 movesvalve 136 as a function of existing power demand, existing steam flowrate, existing grid frequency, and existing HRSG backpressure. Thecooperation of valve 136, controller 162 and sensors 144 are describedfurther below.

Step 404 of exemplary method 400 includes system 100 sensing anover-frequency condition on grid 164 via sensors 120 and 144. Theover-frequency condition may be a result of an addition of, or a poweroutput increase of, one or more generating units 170 or a large decreasein electric power demand by consumers 168 such that a grid frequencyincrease may be greater than 0.5 Hz above the standard frequency.Controller 162 interprets the transient as a demand for a rapid electricpower generation decrease from system 100.

The response of system 100 with the invention to an over-frequencycondition is demonstrated in method step 406 of exemplary method 300.Step 406 includes controller 162 moving valve 136 towards the closedposition. As described above, controller 162 moves valve 136 as afunction of existing power demand, existing steam flow rate, existinggrid frequency, and existing HRSG backpressure. Sensors 144 transmitgrid frequency, STG 142 power output, steam pressures upstream anddownstream of valve 136, mass flow rate of steam to turbine 138, andvalve 136 position feedback to controller 162. Controller 162 comparesthese signals to predetermined values for the associated parameters,i.e., target values, and transmits the appropriate bias signals to valve136.

Method step 408 of exemplary method 300 includes decelerating STG 142and rapidly decreasing STG 142 electric power output as the mass flowrate of steam decreases and the decreased mass flow rate is translatedinto a decreased rate of energy conversion from the thermal energy ofthe steam to the rotational energy of turbine 138. Valve 136 is movedclosed in cooperation with sensors 144 and controller 162 as describedabove such that a substantially instantaneous decrease in power outputof STG 142 is attained.

Method step 410 of exemplary method 400 includes rapidly increasing thethermal energy reserves within the thermal energy reservoir. Controller162 moves valve 136 in a manner that mitigates the rate of increase ofthe thermal reserve residing in HRSG 124, however, the capacity of thethermal reserve is finite and begins to “fill” rapidly at this point inthe system 100 response to the transient.

Method step 412 of exemplary method 400 includes inducing a closingmovement in valve 136 such that valve 136 slowly travels toward thefully closed position, thereby slowly decreasing the mass flow rate ofsteam to turbine 138.

Method step 414 of exemplary method 400 includes slowly decelerating STG142 and slowly decreasing STG output. The controlled, slow rate ofdecrease of the mass flow rate of steam to turbine 138 results in aslow, controlled deceleration of STG 142 with an associated decrease inpower output.

Method step 416 of exemplary method 400 includes mitigating the rate ofthermal energy reserve addition to the thermal energy reservoir.Controlling the initial closing movement of valve 136 such that theinitial thermal energy reserve absorption is controlled and slowlyclosing valve 136 thereafter facilitates mitigating an increase of thethermal energy reserve prior to a reduction of thermal energy fromcombustion turbine 112 can be channeled to HRSG 124 as described below.Step 416 facilitates mitigating the potential for a steam pressureincrease to exceed HRSG 124 component ratings.

Method step 430 of exemplary method 400 includes initiating under-firingof combustion turbine 112 via moving fuel valve 110 towards the closedposition. Step 430 is typically performed substantially simultaneouslywith method step 406.

Method step 432 of exemplary method 400 includes decreasing combustiongas temperature. Decreasing the fuel/air ratio within a range ofpredetermined parameters by decreasing the fuel input into combustionturbine 112 initiates a temporary under-firing condition in turbine 112.Controller 162 transmits a closing signal to valve 110 such that thetemperature of the combustion gas stream is rapidly decreased whilemaintaining the range of gas stream temperature and the rate oftemperature decrease of the gas within predetermined parameters.

Method step 434 of exemplary method 400 includes rapidly deceleratingCTG 116 such that a rapid power output decrease is induced as thethermal energy within the combustion gas stream decreases and turbine112 converts less of the thermal energy to rotational energy.

Method step 436 of exemplary method 400 includes moving vane 102 towardsthe closed position with a subsequent decrease in air flow. Step 436 istypically initiated substantially simultaneously with method step 430.

Method 438 of exemplary method 400 includes decreasing the combustiongas mass flow rate. Gas mass flow rate is decreased as turbine 112decelerates per method step 434 and compressor 104 decelerates withturbine 112 via shaft 114, and vane 102 is moved toward the closedposition per method step 436.

Method 440 of exemplary method 400 includes decreasing CTG 116 output toa value consistent with grid 164 frequency. As the mass flow rate of airinto combustor 106 decreases and the fuel air ratio is returned to apredetermined range of values, controller 162 transmits closing signalsto vane 102 and valve 110 to continue to decelerate CTG 116 such thatmitigating thermal stress parameters of turbine 112 components isfacilitated and CTG 116 attains an output to a value consistent withgrid 164 frequency.

Method step 470 of exemplary method 400 includes decreasing the rate ofthermal energy transfer to the steam/water circuit in HRSG 124. Asturbine 112 exhaust temperature decreases per method step 432 and isfollowed by a decrease in the gas mass flow rate per method step 438,the rate thermal energy transfer from the gas stream into tube banks132, 128 and 126 of HRSG 124 decreases.

Method 472 of exemplary method 400 includes decreasing the pressure andthe thermal energy within HRSG 124. The decreased rate of thermal energytransfer into HRSG 124 thermal energy reservoir counters the thermalenergy addition due to valve 136 closing.

Method 474 of exemplary method 400 includes decreasing steam generationin HRSG 124. The decreased thermal energy transfer within HRSG 124 ismanifested as a decrease in the rate of converting water to steam in thesteam/water circuit.

Method 476 of exemplary method 400 includes transmitting steam to STG142. The subsequent decreasing of the mass flow rate of steam from HRSG124 to turbine 138 permits continued moving of valve 136 toward theclosed position without increasing the thermal energy reserve.

Method step 478 of exemplary method 400 includes decreasing power outputof STG 142 to an output value consistent with grid 164 frequency. Valve136 is further moved towards the closed position at a rate consistentwith the facilitating maintenance of the thermal energy reserve in theHRSG 124 thermal reservoir such that a substantially steady rate ofpower output decrease is facilitated. It is noted that the decreasedthermal energy of the combustion gases from turbine 112 transferred toHRSG 124 is measured and controlled by controller 162 to facilitate theoverall system 100 response.

The discussion of method 400 thus far associated with closing valve 136and replenishing the thermal energy reserve within HRSG 124 assumes alinear rate of valve 136 movement and a linear rate of thermal energyreplenishment. In the event of a more dynamic set of conditions,controller 162 includes sufficient computational resources, includingthe associated programming, to modulate valve 136 more aggressivelythrough the full range of positions between substantially fully open andsubstantially fully closed as necessary to maintain HRSG 124backpressure between a predetermined upper pressure value and apredetermined lower pressure value. Controller 162 modulates HRSG 124backpressure as described above in a manner that also modulates the rateof variation in HRSG 124 backpressure while decelerating STG 138 anddecreasing the thermal energy input rate into HRSG 124 via CTG 112 andduct 122. Given the aforementioned more dynamic conditions and a moreaggressive response, the response may be illustrated as less linear andmore sinusoidal, or saw toothed while maintaining a substantiallydownward slope. Controller 162 includes the computational resources thatmitigate the amplitudes and periods of the sinusoidal or saw-toothedresponse to drive the associated response toward a substantially linearresponse. Additionally, controller 162 modulates the reduction in fueland air to CTG 112 such that system 100 overall response to a grid 166over-frequency condition is a decrease in system 100 output frequency.For example, as valve 136 is moved toward the closed position tomaintain HRSG 124 pressure above a lower threshold limit, CTG 112 rateof deceleration may be reduced to maintain system 100 response. As valve136 is moved toward the open position to maintain HRSG 124 pressurebelow an upper threshold limit, CTG 112 rate of deceleration may beincreased to maintain system 100 response.

The methods and apparatus for an electric power grid frequency controlsub-system described herein facilitate operation of a combined-cyclepower system. More specifically, designing, installing and operating anelectric power grid frequency control sub-system as described abovefacilitates operation of a combined-cycle power system by using thermalenergy storage capacities to facilitate maintaining a standardizedelectric power grid frequency during under-frequency transients on aconnected electric power grid. Furthermore, over-frequency transients onthe connected electric power grid may also be mitigated with theelectric power grid frequency control sub-system. As a result,maintenance of a stable electric power grid frequency may be facilitatedand extended maintenance costs and combined-cycle power system outagesmay be reduced or eliminated.

Although the methods and apparatus described and/or illustrated hereinare described and/or illustrated with respect to methods and apparatusfor a combined-cycle power system, and more specifically, a electricpower grid frequency control sub-system, practice of the methodsdescribed and/or illustrated herein is not limited to electric powergrid frequency control sub-systems nor to combined-cycle power systemsgenerally. Rather, the methods described and/or illustrated herein areapplicable to designing, installing and operating any system.

Exemplary embodiments of electric power grid frequency controlsub-systems as associated with combined-cycle power systems aredescribed above in detail. The methods, apparatus and systems are notlimited to the specific embodiments described herein nor to the specificelectric power grid frequency control sub-system designed, installed andoperated, but rather, the methods of designing, installing and operatingelectric power grid frequency control sub-systems may be utilizedindependently and separately from other methods, apparatus and systemsdescribed herein or to designing, installing and operating componentsnot described herein. For example, other components can also bedesigned, installed and operated using the methods described herein.

While the invention has been described in terms of various specificembodiments, those skilled in the art will recognize that the inventioncan be practiced with modification within the spirit and scope of theclaims.

1. A method of operating a combined-cycle power system coupled to anelectric power grid, the combined-cycle system, including at least oneelectric power generator, at least one steam turbine coupled to thegenerator, at least one combustion turbine coupled to the generator, andat least one steam source having a thermal energy reservoir, the thermalenergy reservoir being in flow communication with the steam turbine viaat least one control valve, said method comprising: operating the steamturbine at a first electric power output, operating the combustionturbine at a first electric power output, and operating the steam sourceat a first thermal energy level, the steam turbine having at least onecontrol valve in a first position, the combustion turbine having atleast one air inlet guide vane in a first position, the steam turbineand the combustion turbine being synchronized to an operating frequencyof the grid, so that the steam turbine, the combustion turbine, and thegrid are operating at a frequency substantially similar to astandardized grid frequency value; and upon sensing a grid frequencydeviation away from the standardized grid frequency value, then: movingthe at least one combustion turbine air inlet guide vane to a secondposition; and moving the at least one steam turbine control valve to asecond position thereby inducing a thermal energy transfer between thethermal energy reservoir and the steam turbine, moving the thermalenergy reservoir energy level to a second energy level, therebyfacilitating a predetermined rate of a grid frequency recovery for apredetermined period of time, the predetermined rate of frequencyrecovery being substantially uniform.
 2. A method in accordance withclaim 1 wherein moving the at least one steam turbine control valve to asecond position comprises increasing a steam mass flow rate to the steamturbine.
 3. A method in accordance with claim 1 wherein moving the atleast one steam turbine control valve to a second position comprisesdecreasing a steam mass flow rate to the steam turbine.
 4. A method inaccordance with claim 1 wherein moving the at least one combustionturbine inlet guide vane to a second position comprises increasing acombustion gas mass flow rate to the combustion turbine.
 5. A method inaccordance with claim 1 wherein moving the at least one combustionturbine inlet guide vane to a second position comprises decreasing acombustion gas mass flow rate to the combustion turbine.
 6. A method inaccordance with claim 1 wherein moving the thermal energy reservoirenergy level to a second energy level comprises decreasing andsubsequently increasing a steam pressure within the steam source. 7-14.(canceled)
 15. A combined-cycle power system, said system comprises: atleast one steam turbine, said steam turbine comprises at least one pipe,said pipe comprises at least one steam flow control valve, said at leastone steam flow control valve being moved toward a substantially openposition in response to a grid under-frequency condition and toward asubstantially closed position in response to a grid over-frequencycondition; at least one steam source in flow communication with saidsteam turbine via said pipe, said steam source comprises at least onethermal energy reservoir, wherein said at least one thermal energyreservoir comprises at least one cavity; at least one combustionturbine, said combustion turbine comprises at least one air inlet guidevane, said at least air one inlet guide vane being moved toward asubstantially open position in response to a grid under-frequencycondition and toward a substantially closed position in response to agrid over-frequency condition; at least one electric power generator,said generator being electrically coupled to an electric power grid,said generator frequency and the grid frequency being synchronized to anoperating frequency of the grid, such that said steam turbine, saidcombustion turbine, and the grid are operating at a frequencysubstantially similar to a standardized grid frequency value; aplurality of process feedback mechanisms, said feedback mechanismscomprise a plurality of process measurement sensors; and at least oneelectronic controller, said at least one electronic controller comprisesat least one electronically stored control program, a plurality ofelectronic input channels, a plurality of electronic output channels,and at least one operator interface device, such that said at least onesteam flow control valve and said at least one air inlet guide vanecooperate to continuously facilitate a predetermined rate of a gridfrequency recovery for a predetermined period of time, such that thepredetermined rate of frequency recovery is substantially uniform.
 16. Acombined-cycle power system in accordance with claim 15 wherein said atleast one steam source comprises a heat recovery steam generator.
 17. Acombined-cycle power system in accordance with claim 15 wherein saidsteam turbine, said combustion turbine, and said generator are rotatablycoupled together on a common rotatable shaft such that said controlvalve, said air inlet guide vane, and said controller cooperate to movesaid control valve and said guide vane toward a substantially openposition to accelerate said common rotatable shaft in response to a gridunder-frequency condition and toward a substantially closed position todecelerate said common rotatable shaft in response to a gridover-frequency condition.
 18. A combined-cycle power system inaccordance with claim 15 wherein at least one generator comprises afirst generator, said first generator being rotatably coupled to saidsteam turbine such that said steam turbine control valve facilitates anacceleration and a deceleration of said first generator.
 19. Acombined-cycle power system in accordance with claim 15 wherein at leastone generator further comprises a second generator, said secondgenerator being rotatably coupled to said combustion turbine such thatsaid combustion turbine air inlet guide vane facilitates an accelerationand a deceleration of said second generator.
 20. A combined-cycle powersystem in accordance with claim 15 wherein said at least one energyreservoir comprises a cavity in flow communication with said steamturbine control valve, said cavity comprises dimensions and a positionwithin said steam source such that sufficient thermal energy storagecapacity to accelerate said steam turbine at a predetermined rate for apredetermined period of time in response to a grid under-frequencycondition is available for release, and said cavity further comprisesdimensions and a position within said steam source such that sufficientthermal energy storage capacity is available to accumulate said steamsource thermal energy at a predetermined rate for a predetermined periodof time in response to a grid over-frequency condition.